1. Field of the Invention
The present invention relates to methods and apparatus for separating and joining tubulars in a wellbore; more particularly, the present invention relates to cutting a tubular in a wellbore using rotational and radial forces brought to bear against a wall of the tubular.
2. Description of the Related Art
In the completion and operation of hydrocarbon wells, it is often necessary to separate one piece of a downhole tubular from another piece in a wellbore. In most instances, bringing the tubular back to surface for a cutting operation is impossible and in all instances it is much more efficient in time and money to separate the pieces in the wellbore. The need to separate tubulars in a wellbore arises in different ways. For example, during drilling and completion of an oil well, tubulars and downhole tools mounted thereon are routinely inserted and removed from the wellbore. In some instances, tools or tubular strings become stuck in the wellbore leading to a “fishing” operation to locate and remove the stuck portion of the apparatus. In these instances, it is often necessary to cut the tubular in the wellbore to remove the run-in string and subsequently remove the tool itself by milling or other means. In another example, a downhole tool such as a packer is run into a wellbore on a run-in string of tubular. The packing member includes a section of tubular or a “tail pipe” hanging from the bottom thereof and it is advantageous to remove this section of tail pipe in the wellbore after the packer has been actuated. In instances where workover is necessary for a well which has slowed or ceased production, downhole tubulars routinely must be removed in order to replace them with new or different tubulars or devices. For example, un-cemented well casing may be removed from a well in order to reuse the casing or to get it out of the way in a producing well.
In yet another example, plug and abandonment methods require tubulars to be cut in a wellbore such as a subsea wellbore in order to seal the well and conform with rules and regulations associated with operation of an oil well offshore. Because the interior of a tubular typically provides a pathway clear of obstructions, and because any annular space around a tubular is limited, prior art devices for downhole tubular cutting typically operate within the interior of the tubular and cut the wall of the tubular from the inside towards the outside.
A prior art example of an apparatus designed to cut a tubular in this fashion includes a cutter run into the interior of a tubular on a run-in string. As the tool reaches a predetermined area of the wellbore where the tubular will be separated, cutting members in the cutting tool are actuated hydraulically and swing outwards from a pivot point on the body of the tool. When the cutting members are actuated, the run-in string with the tool therebelow is rotated and the tubular therearound is cut by the rotation of the cutting members. The foregoing apparatus has some disadvantages. For instance, the knives are constructed to swing outward from a pivot point on the body of the cutting tool and in certain instances, the knives can become jammed between the cutting tool and the interior of the tubular to be cut. In other instances, the cutting members can become jammed in a manner which prevents them from retracting once the cutting operation is complete. In still other examples, the swinging cutting members can become jammed with the lower portion of tubular after it has been separated from the upper portion thereof. Additionally, this type of cutter creates cuttings that are difficult to remove and subsequently causes problems for other downhole tools.
An additional problem associated conventional downhole cutting tools includes the cost and time associated with transporting a run-in string of tubular to a well where a downhole tubular is to be cut. Run-in strings for the cutting tools are expensive, must be long enough to reach that section of downhole tubular to be cut, and require some type of rig in order to transport, bear the weight of, and rotate the cutting tool in the wellbore. Because the oil wells requiring these services are often remotely located, transporting this quantity of equipment to a remote location is expensive and time consuming. While coil tubing has been utilized as a run-in string for downhole cutters, there is still a need to transport the bulky reel of coil tubing to the well site prior to performing the cutting operation.
Other conventional methods and apparatus for cutting tubulars in a wellbore rely upon wireline to transport the cutting tool into the wellbore. However, in these instances the actual separation of the downhole tubular is performed by explosives or chemicals, not by a rotating cutting member. While the use of wireline in these methods avoids time and expense associated with run-in strings of tubulars or coil tubing, chemicals and explosives are dangerous, difficult to transport and the result of their use in a downhole environment is always uncertain.
There is a need therefore, for a method and apparatus for separating downhole tubulars which is more effective and reliable than conventional, downhole cutters.
There is yet a further need for an effective method and apparatus for separating downhole tubulars which does not rely upon a run-in string of tubular or coil tubing to transport the cutting member into the wellbore. There is yet a further need for a method and apparatus of separating downhole tubulars which does not rely on explosives or chemicals. There is a yet a further need for methods and apparatus for connecting a first tubular to a second tubular downhole while ensuring a strong connection therebetween.